Amplify Energy Corp.
Q2 2013 Earnings Call Transcript

Published: 6 Aug 2013

[Operator:]

Good morning. My name is Cassandra, and I will be your conference operator today. At this time, I would like to welcome everyone to the Midstates’ Second Quarter Earnings Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. At this time, I would like to turn the call over to Al Petrie, Investor Relations Coordinator.

[Al Petrie:]

Good morning everyone and welcome to Midstates Petroleum’s second quarter 2013 earnings conference call. Joining me today as speakers on our call are John Crum, Chairman, President and Chief Executive Officer; Steve Pugh, our Executive Vice President and Chief Operating Officer; and Tom Mitchell, our Executive Vice President and CFO. John will begin today’s call with highlights of the second quarter. Steve will then provide more details on second quarter operational results and plans for drilling activity for the third quarter of 2013. Tom will follow with key financial highlights of the second quarter and provide guidance for the third quarter and full year 2013. John will then wrap up with some closing comments. Before we begin, let’s get the administrative details out of the way with our Safe Harbor statement. This conference call may contain forward-looking information and statements regarding Midstates. Any statements included in this conference call or in our press release that address activities, events or developments that Midstates expects, believes, plans, projects, estimates or anticipates will or may occur in the future are forward-looking statement. These include statements regarding reserve and production estimates, oil and natural gas prices, the impact of derivative positions, production expense estimates, cash flow estimate, future financial performance, planned capital expenditures and other matters that are discussed in Midstates filings with the SEC. These statements are based on current expectations and projections about future events, involve known and unknown risks, uncertainties and other factors, that may cause results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Please refer to Midstates’ filings with the SEC in the second quarter Form 10-Q that will be filed shortly for discussion of these risks. Also please note that any non-GAAP financial measures discussed in this call are defined and reconciled to the most directly comparable GAAP measure in the table in yesterday’s earnings release. I will now turn the call over to John for his comments.

[John Crum:]

Thanks, Al. Good morning, everyone, and thanks for joining us today. The second quarter of 2013 was a very busy one for all of us here at Midstates. We achieved encouraging results from a very active drilling program in each of our areas. The biggest news though, was the close of our $620 million acquisition of properties from Panther Energy and their partners giving us a new focus area in the prolific Anadarko Basin. Before we dig into specifics for the quarter. I’d like to begin some comments about the company as a whole. Since we’ve built our team in Midstates. We’ve been clear that we intended to grow the company. Our growth is critical to attracting and retaining top talent. The individuals we are bringing into the company or the kind other companies are trying to attract as well. We’ve been successful in putting a quality team together by showing them the potential to be an integral part of the growth, while continuing to expand their skill sets and to demonstrate their ability to create value for our shareholders and for themselves. This time last year, we were producing less than 8,000 BOEs per day. We were operating only in Louisiana and had just received concerning news associated with a law suit, that back in Pine Prairie, our most valuable asset. Today, after two large acquisitions we are producing around 27,000 BOEs per day from a diversified asset based in three states and have received an order from the Louisiana Supreme Court ruling unanimously in our favor on the Pine Prairie law suit. We are now firmly focused on execution of our drilling and development plans across our asset base to drive growth. The newly acquired Anadarko Basin assets provide us with low risk proven [ph] drilling targets primarily in the Cleveland sands and to well as upside in the numerous known paying with those present in the Anadarko Basin. We closed the Panther acquisition on May 31 as planned, as we discussed the entire Panther staff is under a transition services agreement for six months, to allow for a smooth handover of operations. Panther has built a very strong team. We will be working hard to convince a significant number of those individuals that Midstates will be a good place to continue their career. We entered the Anadarko Basin with a robust inventory of identified drilling locations and have already started a ramp up of activity adding a fourth rig in early July. Operations in the Mississippian continued to move ahead is planned and within expectations. We now have 85 wells that have been on production more than 30 days; those wells have delivered an average 30-day IP of 573 BOEs per day. Steve will provide more detail in a moment, but I’m excited about the significant improvement in our drilling and completion cost and cycle times, as well as to the infrastructure needed to remove the artificial production constraints. Pad drilling has been a key driver for that success in gaining efficiency. Pad drilling operations obviously saves in location roads, pipelines, electrical and construction cost, but it also provide significant savings in our revenues and reductions in our cycle times. As we continue to employee and optimize these techniques, I’m confident more savings will be evident in to 2014. We’ve recently received an initial look at 3-D seismic data that was shot over at the majority of our acreage and are encouraged that we will be able to use the data to assist us with better delineation and de-risking of future drilling locations. Full process is underway. We expect to have the survey results significantly effecting our location and completion selection decisions before the end of the year. Meanwhile, we will be concentrating our activity over the remainder of the year in the most proven of our acreage position in Woods and Alfalfa Counties in Oklahoma. Production from the Mississippian continues to increase month-to-month, but there will be some lumpiness in the growth as we complete and bring on three to four wells on one pad at a time. We’ve made meaningful progress in the horizontal Wilcox program in Louisiana during the quarter by completing four wells. Three of the wells were in North Cowards Gully and one was in South Bearhead Creek. The first well completed during the quarter, the Wood 10H-1 at North Cowards Gully produced its strong initial rates within experienced and mechanical failure. The early flow rates experienced have led us to the decision to sidetrack the well during the third quarter. Steve will discuss how knowledge gained from drilling the Wood well and others was used in drilling and producing subsequent wells and the positive results we’ve experienced with them. Importantly, we also continue our first horizontal lower Wilcox well in South Bearhead Creek there in the quarter. The Musser Davis 33-28 HC-1, the well was drilled within budget and continues to flow at strong rates of over 400 BOEs per day after three months. We will have two more horizontal completions one at North Cowards Gully and ones at South Bearhead Creek during the third quarter. We will monitor production results for number of months before moving to full scale development. Horizontal Wilcox development is difficult as indicated by recent industry colleague comments and by our own trials, as we worked to identify the necessary parameters to achieve commercial success. Our results to-date indicate, we can profitably develop North Cowards Gully and South Bearhead Creek fields with horizontal technology, that we will do so at a measured pace incorporating learning’s into each new well. With that said, our results to-date have also shown us that further development at our West Gordon field is not competitive with the other available investment options in our expanded portfolio at this time. As a result in the second quarter, we wrote off the spud reserves in that field which totaled 4.6 million BOEs. The Pine Prairie we are continuing with inventory generation, while taking full advantage of the new 3-D data recently acquired before doing any further drilling. We are also proceeding with plans for a pilot to evaluate the water flood potential. At Fleetwood, we are developing prospects based on the new 200 square mile processed 3-D seismic survey we received earlier this year. I’m pleased with the third quarter production of 19,634 BOEs per day which was well within our guidance range. We were ready to reach this production rates in spite of some severe weather interruptions affecting those volumes negatively. Most importantly, we have continued to grow those volumes through around 27,000 BOEs per day as a result of both additional success in the Mississippian and in Louisiana as well as adding one-month of new Panther volumes. Many of the initiatives mentioned above, will help provide more stability to the remainder of this year and then to the future. I’ll now turn the call over to Steve and Tom to provide you detailed information on our results.

[Steve Pugh:]

Thank you, John and good morning. And keeping with our normal earnings call format, I’ll discuss second quarter results some of our more recent well results and our operational plans for the third quarter. I will start with the Mid-Continent region, which includes our Mississippian Lime acreage and our newly acquired Anadarko Basin properties. As we announced on the first quarter conference call, we ramped up activity by adding a fifth rig in the Mississippian Lime at the beginning of the second quarter. For the majority of the quarter, four of the rigs were focused on drilling in our most proven area, while the fifth was used to test and hold acreage in the outlying areas. By the end of the quarter, all five rigs were drilling in the more proven area. As John discussed, we participated in the 300 square mile 3-D shoot and we were excited about incorporating the results into our decision making. We invested $77 million in spud 21 operated wells during the quarter of which five were producing, 11 were waiting in completion and five were drilling. Second quarter production in the Mississippian Lime and Hunton averaged 10,426 Boe per day of which 33% was oil and 17% was NGLs. We recorded lower than normal liquids due to approximately 40% of our gas volumes being temporarily bypassed until the new sim [ph] gas Hunton plan was operational, which was June 1st. This bypassing our gas stream resulted in short-term lower realized liquids GL’s and higher gas percentage. We expect the production spilt to be back to normal in the third quarter. We have continued to see significant improvement in our cycle times. During the second quarter, our average spud-to-rig release was below 20 days, a substantial improvement of the 26 days that we averaged during the first quarter of 2013. Three factors that continue to drive this efficiency are the use of the top drives on our rigs. The use of rotary steerables in the curve section of the hull and additional experience in the play. As John mentioned, pad drilling has been one of the key changes, we’ve made in the Mississippian program. We are building pad sites with six well capacity but are currently drilling am maximum of four wells per pad, in an effort to minimize the amount of time needed to bring those wells onto production. Although pad drilling significantly reduces drilling time and provides other cost savings. The timing from spud of the first well to all four wells being brought onto production is roughly 100, 210 days. Moving forward, we will see spikes in production as a larger number of our wells are drilled off of pads and are brought on in groups, but we will also see periods with few completions resulting in some quarter-to-quarter variability in our production growth. We have been proactive with optimizing our SWD and power infrastructure in the region. One of the biggest challenge is when operating in the Mississippian Lime is produced water. Fortunately, due to our concentrated acreage position and efforts to optimize our disposal system 100% of our produced water goes to our SWD wells. Additionally 95% of the frac water for our recent new completions is sourced from produced water, which significantly cuts the use of fresh water in the area. After the major snow storms, we experienced earlier in the year increasing reliability of our powered grid has been a key focus. We have programs in place to lower per unit cost in the long-term including replacing diesel generators with natural gas generators, working with local core ops to upgrade electrical lines, working with other operators in the area to share cost on additional sub-stations and a significant maintenance and upgrade program on our existing grid. We expect these initiatives to yield improved reliability to our power supply. For the third quarter, we plan to spend approximately $105 million in the Mississippian completing the wells awaiting completion and drilling at quarter-end, while spudding 20 to 25 new wells. As you know, we assumed operations on the Panther acquisition properties during the quarter. The company completed three wells during the quarter and spud three additional wells that were still drilling on June 30. We are pleased with the results and plan to ramp up activity throughout the remainder of the year. In the Anadarko properties, we plan to spend approximately $45 million completing wells awaiting completion and drilling in quarter-end, while spudding 15 to 18 new wells during the third quarter. We had a steady quarter in our Gulf Coast region as well. We completed a total of six wells during the quarter of which two were verticals and four were Wilcox horizontals. One vertical well was in Pine Prairie and one was in the South Bearhead Creek field. Both wells are performing through our expectations, of the fourth horizontals completed during the quarter. Three were in North Cowards Gully, where we continue to see consistent results and one was in South Bearhead Creek. In North Cowards Gully, we completed the Musser Davis 8H-2, the Olympia Minerals 16H-1 and the Wood 10H-1. All three wells target to the upper Wilcox B formation. As we previously announced, the Wood 10H-1 was completed early in the quarter and produced a seven-day average IP of 1086 Boe per day, but had mechanical issues they’ve caused it to stop production. We believe, we have identified the solution to the problem and have decided to sidetrack the well in the third quarter. The managed the choke on the Musser Davis 8H-2 and the Olympia Minerals 16H-1 wells, as compared to the previous wells in the area to allow smoother transition as we declined through the over pressured range of the reservoir. The Musser Davis 8H-2 is an offset to the very successfully Musser Davis 8H-1 and was brought on in early June and produced at a 30-day IP of 595 Boe per day, of which 81% was oil and 8% NGLs. The results are encouraging with the well now flowing above 625 Boe per day almost 60 days later. The Olympia Minerals 16H-1 well was drilled and completed with a 4,500 foot lateral which is the longest lateral we drilled in the Louisiana Wilcox. It began production in early July and produced at an average 30-day IP of 751 Boe per day of which 60% was oil and 16% NGLs. These results were also very encouraging as the well is now producing above 675 Boe per day. Although the IPs are lower than previous results, the estimated ultimate recoveries remain consistent. We continue to evaluate the flowing pressures and will slowly open the chokes in order to maximize reservoir recovery. We completed the Musser Davis 33-28 HC-1 in South Bearhead Creek, which was our first horizontal Wilcox well in the field and our first lower Wilcox horizontal. It was brought on in early May and recorded a 30-day IP of 882 Boe per day of which 72% was oil and 11% NGLs. The results from our first lower Wilcox horizontal are encouraging with the well still flowing above 400 Boe per day after three months of production. The second horizontal well in the field, the Musser Davis 8HC-1 is approaching TD targeting the lower Wilcox B Sand. During the third quarter, we expect to spend approximately $25 million drilling and completing two to three horizontal wells. Turning to expenses, our lease operating and workover expenses for the quarter were $17.6 million or $9.83 per Boe, which was higher than guidance. We incurred workover expenses at the beginning of the quarter to bring wells back online following the weather disruptions in the Mississippian coupled with lower than expected production during that period. In addition electricity cost in the area have been more than we expected, which were in the process of remedying with the initiatives I spoke about earlier. In the Gulf Coast region, we had a higher than expected SWD and surface maintenance cost. We have seen our overall LOE cost come down recently as the initiatives we spoke about here and in previous calls take effect. In closing, we are encouraged about our recent well results and plan to continue up to optimized drilling and completion methods across our portfolio. We will remain focused on growing production and implementing additional cost reduction initiatives. As we began integrating the Anadarko assets into our portfolio, we look forward to incorporating Panther’s accounted staff into our organization. I’ll now turn the call over to Tom for financial results and guidance.

[Tom Mitchell:]

Good morning everyone. My comments today will focus primarily upon updating forward guidance with a few second quarter highlights. To begin, second quarter adjusted EBITDA was $65 million after adding back the $11.5 million in acquisition and transaction cost we incurred with the Panther acquisition. This is up 15%, from $57 million in the first quarter. The second quarter benefited from higher production volumes in the Mississippian and one month of production from the new Anadarko Basin properties. We reported net income of $3.3 million in the second quarter compared with a net loss of $7.9 million in the first quarter. Adjusted income for the second quarter which excludes the impact of unrealized gains or losses on derivatives as well as the Panther acquisition transaction cost was a net loss of $4.2 million. Production in the second quarter rose 21% to 19,634 Boe per day from the prior quarter, with 67% coming from Mid-continent properties, 33% from our Gulf Coast properties. In Mid-Continent our Mississippian and Hunton properties averaged 10,426 Boe per day, while our new Anadarko Basin properties contributed 2,068 Boe per day to the quarter that reflects one-month only of production for Panther in June. Our guidance for the product breakdown remains as previously provided. As Steve discussed, we did experience a lower percentage of liquids in the Mississippian and Hunton product breakdown during the second quarter, but the lower liquids waiting was temporary for the evenly mentioned. Looking ahead to the third quarter, we expect production to be in the range 27,000 to 28,000 Boe per day with about 50% from our Mississippian and Hunton properties, 30% from our Anadarko properties and 20% from Louisiana. For the full year 2013, we’ve narrowed our range by reducing the upper end of our guidance range to reflect the weather related downtime we faced in the first half of the year. Annual guidance is now 24,000 Boe to 25,000 Boe per day. The impact of pad drilling in Oklahoma result in number of wells coming online concurrently in September which tempers growth in the third quarter, but will result in meaningful volume increases in the fourth. The regional product breakdowns as well as expected realizations differential including transportation remain unchanged from prior guidance in all reflected in the updated guidance summary posted to our website. In our last quarterly call, we discussed our intent to add new hedge positions to cover the Panther acquisition volumes. We added those positions shortly after closing the deal on May 31. For oil, we had positions covering 4,500 barrels per day for the remainder of 2013, 5,250 barrels per day in 2014 and 1,000 barrels per day in 2015. For gas, we’ve added 40,000 Mmbtu per day for the remainder of ‘13, and 25,000 Mmbtu for the full year 2014. These trades take our hedge positions for oil and gas near the maximum allowed under our credit facility which is our ongoing target. Going forward, we will add hedge positions as production gross. The earnings release include detailed information on price realization as well as a summary of the current hedge position. Let’s now turn attention to review expenses as Steve discussed. Our lease operating and workover expenses of $9.83 of barrel for the second quarter was above expectation for the regions mentioned. For the third quarter, as our cost initiatives take effect, we expect LOE to trend lower and couple with higher quarterly volumes to be in the range of $8.50 to $8.75 per Boe. We are adjusting full year LOE guidance $0.50 per Boe to a range of $8 per Boe to $8.50 per Boe taking into account the higher cost that we’ve already experienced. Severance and ad valorem taxes were 6.4% sales revenue and that’s before derivatives. A bit lower than the 8% to 7%, to 8% rate we guided to for the quarter, for both third quarter and full year 2013, we’ve lowered guidance to 6% to 7% of revenue, which should reflect the new blend of production from Louisiana, Oklahoma and now Texas. Second quarter general and administrative expense was $15.3 million, which was above guidance and as primarily due to the pace and headcount additions. At the second quarter included non-cash compensation of $1.8 million and about $2.3 million of transition services cost with $1.7 million related to Panther acquisition and the balance for the Eagle acquisition. We expect G&A in the third quarter to be in the range of $14 million to $16 million and the total year to be unchanged in the range of $49 million to $53 million, 10% to 15% of that G&A amount will be non-cash compensation. Our DD&A rate in the second quarter was $29.56 per Boe in line with our expectations. Despite the impact of West Gordon which John mentioned, the second quarter DD&A rate remained within our guidance. We’ve narrowed our guidance for the third quarter and full year 2013 to $28 per Boe, $30 per Boe. Total interest expense incurred in the second quarter was $24.50 million. We expensed $16.6 million in capitalized 32% or $7.9 million. Going forward, we expect to capitalize to unproved properties $10 million in the third quarter and $35 million to $40 million for the full year. During the second quarter, we invested approximately $141 million in capital expenditures with $77 million in our Mississippian properties and $6 million to our new Anadarko Basin properties. The balance of $58 million was spent in the Gulf Coast area. For the third quarter, we expect to invest $170 million to $180 million with about 60% in the Mississippian, 25% in Anadarko and the balance in the Gulf Coast. The full year guidance was narrowed to $550 million to $575 million and the split by area is provided on a guidance page. On May 31, concurrent with the closing and the Panther deal. We completed a private issuance of $700 million of 9.25% senior notes. The $683 million in net proceeds were used to fund the acquisition and to provide liquidity. Additionally, a revolver was amended to increase the borrowing base to $425 million. With our current drilling programs focused on efficiently adding proved reserves. Which are the primary support to the borrowing base, we expect to see a strong increase in the borrowing base during the coming September redetermination. On June 30, 2013 liquidity was $216 million consisting of $204 million of available borrowing base under the credit facility and $12 million of cash. Our strategy to the end of the year and into 2014 is to grow cash flow, while employing conservative capital allocation. Not only that we put hedges in place to protect against commodity price exposure, we’ve lined out our rig programs to reflect the most optimal growth of EBITDA and cash flow. We feel that, through these initiatives we can actively manage our liquidity while also providing a sustainable growth profile and with that. Let me now turn the call back over to John.

[John Crum:]

Thanks, Tom. As you’ve heard today we had a very busy second quarter and an even more active third quarter is well underway. As we developed our plans for later this year and into ‘14. We will incorporate the knowledge we are gaining in each of our three focused areas into our drilling and capital plans. In Louisiana, we believe we have a much better understanding of what works in the Wilcox. In the DeQuincy area, we will finalize our drilling plans after monitoring our horizontal well performance in the near term. In the Pine Prairie and Fleetwood areas, we will develop our drilling program based on the new 3-D data we required. In the Mississippian, we will update our drilling program based on significant success we’ve had with reducing cycle times and focus our drilling in those areas, where we’ve had the best results. In the Anadarko, we’ve used the knowledge we’ve gained in the Mississippian, as we ramp up activity at a measured pace to optimize drilling program in that new area. In summary, we remained 100% focused on execution of our plan to drive organic growth and I’m closely managing our capital allocation process and with that, I’ll turn it over for questions. Al?

[Operator:]

(Operator Instructions) your first question comes from the line of Neal Dingmann with SunTrust.

[John Crum:]

Good morning, Neal.

[Neal Dingmann:]

Good morning, John. Say John just going through a little bit you mentioned, I’m just wondering on the Gulf Coast operation. It does sound like, you’re making some progress there and deciding and kind of what and where to drill, give me an idea on Wilcox. I know that, Musser Davis 8H-2 was down to $10 million, what are you kind of assuming, you and Tom when you look at the budget now for the remainder of the year, on these well cost. In order to be economic, I guess what are you going to need a hit on a go forward basis for some of these, maybe the upper or lower Wilcox?

[John Crum:]

Well on the Upper Wilcox First of all, the $10 million range will be economic. Obviously, we’d like the economics get better. We would expect to be able to drive those numbers back into the eights before we’re done, that North Cowards Gully especially as we get into real program. On the deeper, in the lower Wilcox obviously we’re setting another string of casing. We are going into another pressured zone. We did spend an excess of $13 million on that first South Bearhead well, but again we expect those numbers be pulling back and we’d be in the $11 million range an ongoing effort there. The well we are drilling right now, is right on schedule and we expect to TD it, in the next day or so, they’re within, I guess they’re 800 feet off TD yesterday, so we feel pretty good about it. It’s a feet [ph] at $11.5 million.

[Neal Dingmann:]

Okay and then just my follow-up, moving over on just the horizontals. Two things there John, on infrastructure wise, it still seems like you’re keeping up if not, ahead where you need to be there and then just, on cycle times. Can those continue to, you really had a material improvement there, what are you kind of assuming on a go forward? Can that continue to improve beyond the 20 days or kind of the rates now that you’re hoping for?

[John Crum:]

Yes, we are little bit nervous about putting the stick out there for you guys to measure us against, but I will tell you that third quarter-to-date, we are less than the number, we told you about second quarter. So we feel like, obviously this pad drilling helps a lot. When you’re drilling three or four wells off the same pad? It makes all the difference in the world. Rig measure is typically taken about five days and we change that to one day. So good run in start and obviously we don’t build three or four pads. So those are all helping with the numbers.

[Steve Pugh:]

Yes, just Neal just another comment. The numbers that we gave you, the 20 days that is spud to rig release so that actually doesn’t pull in the pad sites. I mean, we start that talk after spud and that’s the number that John is saying in the third quarter, so far we are seeing numbers still below the 20 number, that we showed you and we will talk more about on the next call.

[Neal Dingmann:]

Good, that’s great to hear. Thanks, Steve.

[John Crum:]

Thank you. Neal.

[Operator:]

Your next question comes from the line of Jeb Bachmann from Howard Wiel.

[Jeb Bachmann:]

Good morning, guys. Just want to look at the go forward EBITDA number looking into ‘14, kind of you guys make move internally probably looked at that and what you could potentially generate, just give us some idea of how you think, you can grow that number in ‘14 and kind of what’s your targeted debt to EBITDA coverage is for the end of ‘14?

[John Crum:]

Jeb, I don’t know that we are ready to give you those numbers yet. Obviously we just took these Panther assets in and if you can bear with us a little while we kind of put some thoughts together on that, we’ll be coming out with some better feeds for it, in another two or three months, but we really feel like we need to see how that’s performing before we give you a solid ‘14 estimate.

[Jeb Bachmann:]

Okay and then just looking at, you made a comment about the competitor in your commentary on potential Louisiana assets. Two questions there; one would you guys look at those assets and two; if those assets are sold for good price, would you guys look at potentially divesting your position there as well?

[John Crum:]

No that’s an interesting spin on it. I guess first of all, I would tell you that we do like their acreage, but at the same time. As you’re well aware, we’ve got our boat pretty loaded right now. So we’d have to take a look at it and obviously if it is a number that kind of blow your doors off, then you probably have to think about whether or not it made sense for you as well.

[Jeb Bachmann:]

Okay, great. Thanks, John.

[Operator:]

Our next question comes from the line of Ron Mills from Johnson Rice.

[Ron Mills:]

Jeb just asked one of my questions. Maybe I tag along on the Wilcox, one of things; I think swift experience was higher cost and some with production issues. Is this similar to what you experienced certainly on and as you moved up to learning curve, is that something that prompts you to like their acreages as well or is it geologically similar? I’m just trying to get a sense as to comparing what happened to you initially in the horizontal program versus where you’re now having drilled the number of wells?

[John Crum:]

Yes, I think you listen to it. We went through some pain in this exercise as well and they’re not easy wells to drill, but our guys are knock on wood. We feel like, we’ve kind of got this figured out. We know what, what we are trying to – how to drill them and we think we know how to complete them, and then hopefully pick the right places. As far as the acreage goes, obviously geology is what really counts and we would argue that South Bearhead structure is a big structure and they have a significant amount of it, so yes it’s good geology, that’s where we go for first.

[Ron Mills:]

Okay good and then with Mississippian sounding like it’s kind of in the middle of the fairway in terms of well performance, good to move to the Panther properties. You’re just getting really started up there. You’re going to ramping activity, is all of the activity over the remainder of this year, going to remain focused on the Cleveland or at what point do you think, you started testing some of the other formations and then, when you do that, are your guys, as you started to kick the tires, what your guys think about the opportunity set and or opportunity for improvements in your shop versus the prior operator?

[John Crum:]

Well I think, as we described when we bought this asset. I think the Panther guys would tell you, they were cut back on capital available to them. We think it’s a great asset base that has lots of drilling potential. We have already added a fourth rig and that rig is indeed drilling in Marmaton [ph] well. So we would expect, the three rigs working on Cleveland which is clearly the core of the play. We’re pleased to see some other operators coming out, with some recent information about performance in some of that area and we hope they’re dead right because obviously that will be good news for us.

[Ron Mills:]

All right, everything else been asked. Thank you.

[John Crum:]

Thank you.

[Operator:]

Your next question comes from the line of Brad (inaudible) from Wells Fargo.

[John Crum:]

Hi, Brad.

[Unidentified Analyst:]

Thanks, John and good morning everyone. Two quick questions, I guess both focused on Louisiana. First one; John you’d mentioned you’d looking towards that Olympia Minerals well is guide for how far south the structural go in the area for North Cowards Gully. I think you put the location count for horizontals around 20 or just above 20. Just curious, I know it’s still early with only 30 days on production or so but, what are your initial thoughts on that and are you able to say now, that you’re pretty optimistic that the structures continues to the south there?

[John Crum:]

Yes, we sure are there, the Olympia Minerals is turned out to be a very good well. And I think the issue is, we are just trying not to get ahead of ourselves and so we’d like to produce it few months before we jump off and drill another one looks just like it, but we are very pleased with what we’ve seen. Steve tried to describe some of the issues that kind of goes back to one of Ron’s questions, about some of our colleagues. We end up in drilling these wells, we are learning a few tricks and we think one of them is, to kind of bring the pressure down slowly, especially as we move out of the over pressured region and so Steve talked about managing chokes and that’s one of the big effort on our part. The catch with that, of course it limits the IP that you’re going to see, but I can assure you those three wells that we’ve talked about, would absolutely have three digits on their IP, if we’d open them up, there is not any question.

[Unidentified Analyst:]

Okay, great. Thank you and then second one, John you touched on it during the prepared remarks, but going over to the Fleetwood seismic shoot, have you chosen the first location and I was hoping, if you could give us more color on any potential second half activity over there in that area?

[John Crum:]

While we’ve gotten a new exploration VP that joined us during the quarter and we’ve got him working on that pretty hard. You got any comments? Greg?

[Greg Hebertson:]

Sure, Brad thanks for the question.

[John Crum:]

I didn’t tell him. He’d be on here.

[Greg Hebertson:]

Good to meet everyone. We’ve developed a number of leads on that inventory is probably six or seven opportunities. I would say, we are maturing two or three of them and it’s possible that we could be testing something later this year, but it’s more likely early Q1, 2014.

[Unidentified Analyst:]

Got that, okay great. Thank you very much.

[Greg Hebertson:]

Brad, one thing just to go back to the Olympia Minerals. We drilled that well from south to north and we drilled a pilot and got a real good looking log on the South End. So that’s why we are pretty optimistic, that we still don’t know where the down dip limit is on the South. And as we looked at our 3-D, we also see kind of the same thing on the East side, which we didn’t know before.

[Unidentified Analyst:]

Okay, that’s helpful. I appreciate your time. Thank you.

[John Crum:]

Thanks, Brad.

[Operator:]

Your next question comes from the line of John Herlin [ph] from Sigeneral [ph].

[John Crum:]

Good morning, John.

[Unidentified Analyst:]

Yes, how are you? Anyway, with the Gulf Coast, you’re going in a more controlled flow back manner, with the horizontals what kind of an EUR increase do you think, you might get out of these wells or is it just a matter of not having mechanical issues and then with the respect to the Wood well, what was the postmortem on those mechanical issues, what happened you just ended up or what?

[John Crum:]

Well, we are not completely sure, but we did get some formation cuttings coming into the wellbore, we went in coil tubing and couldn’t get down. So whether the casing jumped the collar or collapsed or whatever, we don’t know exactly what the answer is, but the well came on so strong, we feel very good about the location geologically and we have been, I got to say, we’ve been running the ported systems with the packers and we kind of moved away from that and you’ll see us doing all plugging going forward. We feel like putting the cemented liner may make a difference flowing them back slower may make a difference and I wish I could tell you exactly what’s solving the problems that we are attacking it from all fronts?

[Unidentified Analyst:]

Okay that’s fine. Tom, you mentioned that you’re bank credit line will be reviewed in the fourth quarter. You have any idea what kind of ball park, what you think it’s going to?

[Tom Mitchell:]

I don’t have a number John, but we’ve been looking at it intently, since this is the first redetermination post the transaction with the new assets and everything. It looks very strong, I’m expecting a pretty robust redetermination, which should bolster the liquidity and one thing that helps there is the hedging transaction that we put on that will add to it as well as the program has been adding the harder board support, the borrowing base the PDP. So my expectation is that, are pretty strongly determination and it comes in right at the end of September. So we are working on it intently in fact, we’ve already started with the reservoir engineering at the lead bank and expect have a number late September, early October.

[Unidentified Analyst:]

Okay, great. Last one from me. With West Gordon was it mainly spud removed?

[John Crum:]

Yes it was John.

[Unidentified Analyst:]

All right. Thank you.

[John Crum:]

Thank you.

[Operator:]

Your next question comes from the line of Pavan Hoskote from Goldman Sachs.

[John Crum:]

Good morning, Pavan.

[Pavan Hoskote:]

Good morning, I’ve one from Brian Singer. In your opening remarks, you indicated that you recently received 3-D seismic data in your missed line play. How do you see 3-D seismic helping you reduce the volatility and IP rates from the play, given that some other operators that you’re most skeptical on the efficacy of 3-D seismic and I have a follow-up please?

[John Crum:]

Yes, I can tell you that. we are well aware the skepticism associated with it, but Midstates and Chesapeake went together and shot this fairly extensive survey covering significant part of Woods and Alfalfa Counties and all I can tell you, we are seeing things that are certainly interesting if we haven’t figured out exactly how they apply, but I think what we feel about 3-D seismic is number one, it’s going to answer a few questions for us, but what we are hoping it, it will help us avoid the problem wells as much as find the best areas. So Greg, do you have anything to add to that?

[Greg Hebertson:]

Yes, I think that’s an accurate statement John. I think I would add is, 3-D seismic is a critical tool understanding the whole reservoir characterization. So we have log data, we have some core data and now we have some 3-D seismic data that allows us to integrate all three of those pieces of data to optimize well locations and understand the play better.

[Pavan Hoskote:]

Great, thanks John and Greg and then moving onto the Anadarko Basin. At the time of the Panther acquisition, you indicated that the Cleveland formation was your primary target. Based on any additional work you may have done since, do you have more or less confidence in the prospectivity [ph] of other zones in the area?

[John Crum:]

Yes, I think we are feeling about it, Curtis Newstrom, who’s done our Business Development kind of from the start. As we told you, we are not buying anything right now. So he’s been working full time on this transition. I might, have him make a comment or two about that.

[Curtis Newstrom:]

Yes, as far as the objectives that Cleveland is the primary, the first two rigs, but we do, we’ve done a lot of studying of the other locations and we are pretty excited about the Marmaton and then stepping, we’ve had some active Cottage Grove work going on, we haven’t drilled a lot of Tonkawa at this point, which is been a lot of offset performance that’s very encouraging. So we are probably more excited about the other intervals beyond the Cleveland than originally and this is a integration point. We are still working with the Panther folks transitioning through it and trying to figure out what our long-term plan is, we picked up another rig and we will be looking at what our plans are in some of the other areas beyond the Cleveland for the next couple months.

[John Crum:]

Yes and we are obviously watching other industry activity and we are well aware, there are some pretty flashy numbers coming out there. So we hope to be mirroring those.

[Pavan Hoskote:]

Thanks a lot.

[Operator:]

Your next question comes from the line Stephen Shepherd from Simmons & Company.

[John Crum:]

Good morning, Stephen.

[Stephen Shepherd:]

Good morning, so the three horizontal wells that you all reported out in Louisiana for the quarter had an average 30-day rate of about 750 Boe a day. What’s at the EUR, would you anticipate a 750 Boe a day well would produce based on counting your average model tight curve in Louisiana?

[John Crum:]

Yes, I don’t think we’ve actually given you tight curve on our horizontal wells in and that’s because I guess we needed to see a little performance before we could come up with something that would tell you anything. I can tell you the one well that we’ve had on for significant amount of time that Musser Davis 8H-1 which came on in September of last year, does appear to be headed up certainly into the high fours. We don’t know what these others are going to do and hopefully, we are going to have some additional information in the future, keeping in mind what we talked about earlier. We are holding that those last three wells back. We could have float them at higher rates in that. None of them are have any gas left going through them yet. We are about to put it one of them, but these are been flowing back up the frac strings for the last several months.

[Stephen Shepherd:]

Now that’s helpful, thank you and one more if I can. At this point, how many engineered horizontal locations, do you think you all have in the Gulf Coast region?

[John Crum:]

Well, I wish I could kind of pin that down, but let me just say we think we have in excess of 20 at North Cowards Gully and still feel very good about that number. Obviously we are on flown for a while and make sure they’re going to hang in there because these are expensive wells. As South Bearhead Creek, the game there is going to be how many of those intervals can we go into, so we’ve got a test in the sea sand at the South Bearhead Creek and we are about to test the D in the lower, but at South Bearhead Creek, there is seven different pay horizons that we produce out of so. I guess, as we test these and find out how many and we can go horizontal and that will determine how many ultimate locations we can put in.

[Stephen Shepherd:]

Great information. I appreciate it, thank you.

[Operator:]

Your next question comes from the line Ipsit Mohanty from Canaccord.

[John Crum:]

Good morning, Ipsit.

[Ipsit Mohanty:]

If you just look past this quarter and you spelled out why, probably the gas still was a little higher in the Miss Lime wealth. Do you still retain the overall yield mix in the Miss Lime as 40% oil, 20% NGL, 40% gas is that consistent?

[John Crum:]

Yes, we still feel pretty good about those numbers. We get out of this problem, Steve described we are putting in that new plant and so we had to bypass the plant for a significant amount of time.

[Ipsit Mohanty:]

And my second question is on the well cost, given the various initiatives that you’re doing. Would you still maintain the $3.7 million number for Miss Lime and probably the $2 million for the Cleveland well assets, is that consistent $2.50 million probably?

[John Crum:]

Well I think the Cleveland wells are higher than that, we would have said high two’s on the Cleveland obviously depending on how many frac jobs you put on it, but I think it’s been pretty standard to put 15 or 16 stages of fracs on those wells, so that kind of puts you $1.5 million or so just on the frac jobs. So on the other wells; our target is still to bring the cost down into the low three’s on a Mississippian well as we go along.

[Ipsit Mohanty:]

And then do you still plan to end the year with six rigs in your Anadarko Basin assets, is that still the plan?

[John Crum:]

We are working that right now and well I’d say, as we just put the fourth rig to work and we are confident we will put a fifth rig to work and we will see how it goes. If we are getting the kind of performance we hoped, then we’ll have to make that call, but I guess I’d say we are going to make sure; we are proceeding at the right pace.

[Ipsit Mohanty:]

Thanks, guys.

[John Crum:]

Thank you.

[Operator:]

The next question comes from the line of Kyle Rose from RBC.

[John Crum:]

Hi, Kyle. Good morning.

[Kyle Rose:]

Hi guys, most of my have been asked but a just a quick housekeeping one from me. I know that your basic share count picked up a little bit this quarter; can you guys speak to that?

[Tom Mitchell:]

It would be restricted share grants probably what you’re saying. Vesting, the first initial vesting of the IPO grants, is what you’re saying.

[Kyle Rose:]

Got it. Okay, thanks guys.

[Operator:]

Your next question comes from the line of David (inaudible) from (inaudible) Energy.

[John Crum:]

David, how are you?

[Unidentified Analyst:]

Doing really well. Can you just walk through of the buildup of your $105 million of capital in the third quarter? How much of that 20, 25 new wells but how is it going to be in facilities, how much is completing the backlog of well, rebuilt in the second quarter and just kind of some granularity on that 105, into this line?

[John Crum:]

Yes, we may have to call you back but in the Miss Lime obviously most of this is around drilling, but we are also installing some gas-fired generators and continue to upgrade some of the power line, so there is some. How much we’ve got? Total of $9 million for the year, you better help me with this real quick, just a second. I’ll tell you. Okay, 86 on DMC, seismic and Lime 10 and facilities 9, that’s third quarter.

[Unidentified Analyst:]

Okay, that’s helpful. Thanks guys.

[John Crum:]

That’s pretty correct.

[Unidentified Analyst:]

That’s all I needed. Thanks.

[John Crum:]

Thank you, David.

[Operator:]

And we have time for one more question and your final question comes from the line of Shawn Steven with Oppenheimer.

[John Crum:]

Hi, Shawn.

[Shawn Stevens:]

Hi good morning, thanks for taking the question. Tom or John, you guys have done a pretty good job of building your inventory, throughout the last six to nine months and really pendulant scale just over $200 million liquidity, can you talk about your appetite for any further acquisition?

[John Crum:]

I think we have made it pretty clear, we feel like our boat is pretty loaded. So you can expect us to just keep our nose down and perform on the assets we’ve got. We know that many of you investors our there that’s what you’re looking for, sure we can make that work. So that’s what you’re going to see us focused on, after we put some as one of our investors some boring quarters together, then we can have another conversations, but we know we need to perform on what we’ve got right now.

[Shawn Stevens:]

Sure that makes sense and then just looking at your CapEx guidance for the rest of the year. It would appear that, the Q4 level is going to be down sequentially from Q3 is that are you dropping a rig or what’s the driver behind that?

[John Crum:]

Yes, that would be dropping some rigs. We have told you kind of from the start, we are going to try to show some capital discipline here and the good news is, we are drilling these wells a little faster than we expected. So we are going to be able to get the number wells that we need to maintain the production rates, but we are just going to do it faster. So that’s what you’re seeing happening there.

[Shawn Stevens:]

Got you and then somewhat relatively, on the leverage side. Just over four times now, I guess on a Performa basis. I guess, first are you comfortable in that in where would you like to be?

[Tom Mitchell:]

Nothing is really changed Shawn from what we’ve talked about as far as our expectations and our targets going on in the next year and our view is that we will be down closer, if not below that three level, by the time we get to the end of 2014 and that’s what we are driving for and the efforts that you see right now are not just the growth of production, but risk mitigating in that regard you get a pretty substantial hedge program, you can see what we’d had it. That won’t be the end of that, we will follow that quarterly as the production goes up and then we are drilling in the heart of our acreage right now, to beat up that cash flow in earnings.

[Shawn Stevens:]

Okay and is there any, would you guys ever consider asset sales or anything else to kind of expedite the deleveraging plans you got one there?

[Tom Mitchell:]

Right now, we will execute on what we’ve got, we are looking at all the different alternatives and that would certainly be one, which would not have been available to us at the small portfolio we had a year ago. So what we got under our belt right now, it gives us the opportunity to look ahead and optimize it. So we will look at everything to balance that. We are clearly aware where it is and it got pretty strong target to bring it down and that’s, that will be the effort here as we go forward.

[Shawn Stevens:]

Sure, that makes sense. Thank you very much.

[John Crum:]

Thank you.

[Operator:]

You have no further questions.

[John Crum:]

Well, thank you and no further questions. I appreciate you all joining us this morning. We are extremely busy and we hope, we are showing we are kind of hitting the numbers and we will continue to work those cost down and you’ll see better performance as we go forward. Thank you for your time, this morning.

[Operator:]

This concludes today’s conference call. You may now disconnect.